In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without many of these details and that numerous variations or modifications from the described embodiments may be possible.
In the specification and appended claims: the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via another element”; and the term “set” is used to mean “one element” or “more than one element”. As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly described some embodiments of the invention. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or other relationship as appropriate.
Well/formation testing is one of the primary techniques to explore subsurface formation properties. A typical objective of a well/formation test includes measuring bottom-hole pressure (BHP) or flowline pressure transient during flowing and shutting-in of the well/pump as well as capturing representative reservoir fluid samples. The BHP or flowline pressure history can be used to infer formation permeability or productivity, damaged skin factor and initial reservoir pressure. The reservoir fluid samples are used in laboratory to measure the fluid properties, such as viscosity, compressibility, gas-oil-ratio, formation volume factor etc. Because these fluid properties play a major role in determining reservoir performance and designing optimum field operations, high quality reservoir fluid properties are needed in reservoir management. That, in turn, requires high quality representative fluid samples from a well/formation test.
The reservoir fluid sampling is usually conducted through a wireline formation tester (WFT) or a dedicated sampling operation in a large scale well test called Drill Stem Test (DST). There are two major issues that affect the quality of fluid samples taken by either WFT or DST in the fluid sampling. The first is contaminations of mud (or completion) filtrates in the samples. The second is unwanted phase change in the samples during the test as the samples may experience a pressure below the bubble or dew point pressure before they are captured. Mud filtrates exist because of over-balanced pressure differential between the wellbore and formation during drilling operations. If the filtrates are not completely removed or separated from the virgin reservoir fluids before the samples are taken, the quality of the samples can be compromised. Gas vaporization or condensates drop out when the fluid pressure goes below the bubble or dew point, leading to phase change in the fluid samples. If the samples are contaminated or non-representative components are present in the samples, inaccurate measurements of the fluid properties can result. WFT and DST both have advantages and limitations in dealing with the above two difficulties in fluid sampling.
A wireline formation tester, such as the Modular Formation Dynamic Tester™ (MDT), available from Schlumberger Technology Corporation, is often used to take the fluid samples soon after a well is drilled. The formation tester uses either a dual-packer to isolate a small segment of the wellbore or a probe against the wellbore sandface. A pump installed in the tool string withdraws formation fluids through the dual packer or the probe into a flowline of the tool. Because drilling mud filtrate exists in the near wellbore region, the initial fluids pumped in the flowline are mostly filtrates rather than virgin formation fluids. The characteristics of the fluids in the flowline can be monitored by various sensors installed in the flow channels in the tool string. For example, an optical density sensor, as described in the U.S. Pat. Nos. 4,994,671, 5,266,800 and 6,966,234, may be used to distinguish the filtrates and formation fluids. If the filtrate level is high, the produced fluids are dumped into the wellbore and pumping out is continued. If the contamination level is below an acceptable level, the withdrawn fluids are diverted into a sampler to capture the fluid sample. Because mud filtrates usually still exist during the pumping out stage, it is very difficult to obtain contamination free fluid samples even using a guarded probe that is available from Schlumberger Technology Corporation and is described in the U.S. Pat. No. 7,178,591. However, real time communication and data transmission are available in WFT, the bottom-hole pressure can be continuously monitored. In most cases, flow rate can be reduced to accommodate single phase sampling requirements in order to maintain the fluid pressure above the bubble point or dew point pressure. Therefore, WFT has better capability to control fluid pressure in a flowline above the bubble or dew point in most conditions so that single gas or liquid phase sampling can be obtained, but mud contamination is more difficult to overcome.
Drill stem test (DST) is another technology often used in fluid sampling. A variety of testing tools including fluid samplers are installed at the lower end of working pipes that are run into the bottom of the wellbore and are set close to the formation to be tested. Formation fluids are induced into wellbore, working string and even on the surface while the BHP is recorded during the flowing and subsequent shutting in periods of the well test. A dedicated flowing period is often carried out at the end of the test to capture formation fluid samples. Because wireline or other types of communications usually are not available for a DST, it is difficult to monitor the compositions of fluids or pressure condition inside the wellbore before taking the samples. However, since working pipes are used in the test, a large quantity of formation fluids can be produced into wellbore, working pipe or on the surface. If the produced formation fluid volume is sufficiently large, the mud filtrates can be completely removed from the well before representative fluid samples are captured. Contrary to WFT, a very low level of, even no, contamination in fluid samples may be achieved in a DST. Thus, while DST is capable of obtaining contamination free fluid samples it is generally difficult to know whether there ever was/is gas vaporization or condensate in the fluids during the sampling operation because of an absence of the real time monitoring.
Sometimes, even though the captured fluid samples do not have vaporized gas or gas condensate, it does not guarantee the samples have representative components as the virgin reservoir fluids. The reason is that the formation pressure might decrease below the bubble or dew point before the time of the sampling. For some test operations, the wellbore pressure has the lowest value at the initial time of production and then continuously increases during the later production and well shutting-in. For example, during a closed chamber test (CCT) or during a slug test of a DST, the initial wellbore pressure can be quite small resulting from a small liquid cushion used in the test. Depending on formation and fluid properties, the reservoir fluid deep inside the formation may also experience a low pressure, which may cause gas vaporization or liquid condensate to drop out. Since more and more formation fluids move into wellbore as the test progresses, the hydrostatic pressure inside wellbore increases along with the rising liquid cushion column. The wellbore pressure at the late time of the test may return to pressures that are higher than the bubble or dew point pressure. At the time of the sampling, the wellbore pressure is higher than the bubble or dew point, so single phase samples can be obtained. However, because the fluid samples have experienced pressure below the bubble or dew point at the initial test time, the composition of the samples may still be compromised.
In some other situations, the opposite may be true. In other words, even though the wellbore pressure at the initial test time is below the bubble or dew point, the pressure of the captured samples may not have gone below the critical pressure in a CCT or a slug test. The reason is that the wellbore pressure progressively increases during the test and the sampling is conducted at a time toward the end of the test, during which the wellbore pressure has already increased above the bubble or dew point pressure. The fluid parcel that experiences pressure below the bubble or dew point at the early test time is lifted to the upper portion of the working pipes or even to the surface. The samples captured in the samplers at the time toward the end of the test may not have experienced any pressure below the bubble or dew point. Thus, the captured samples are still high quality.
Currently, existence or absence of the phase change in the samples is only qualitatively judged by the bottom-hole pressure measurements. The above analysis indicates that quantifying whether there is phase change in the captured samples in many test operations, especially, in CCTs and slug tests, is a complicated issue. In general, the quality of the samples cannot be quantified directly based on the bottom-hole pressure in a well test or flowline pressure in WFT since the samples taken into the samplers may have experienced very complex and different pressure history. Continuous improvement in relation to that area is needed.
The present application addresses the discussion so far herein and many, if not all, of the related drawbacks and associated issues. A detailed description of some embodiments follows herein.